In drilling operations for the exploration of oil and gas, various fluids are used during different stages of drilling, production, and completion of a well. For example, a liquid slurry known as drilling fluid (i.e., drilling mud) is used for maintenance and lubrication of the borehole created during the drilling operation. The fluids used may be referred to as wellbore fluids, which may include drilling fluids, production fluids, and completion fluids. A wellbore fluid system of a well includes a mud holding tank at the well surface located on or adjacent to the drilling rig and a network of pumps, mixers, and fluid supply lines. During drilling operations, wellbore fluid is pumped from the mud holding tank, through the fluid supply lines, down through the wellbore and circulated at a desired rate, and is returned to the surface of the wellbore. The returned wellbore fluid carries with it drill cuttings from the bottom of the borehole produced as drilling advances. As such, during this circulation, the wellbore fluid may act to remove drill cuttings from the bottom of the hole to the surface, but may also be used to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
When the circulating wellbore fluid, along with the carried drill cuttings is returned to the surface, it is delivered to a screening device known as a shaker that serves as a sieve for removing the carried drilling cuttings from the wellbore fluid. When the drill cuttings have been removed from the wellbore fluid by the shaker, the wellbore fluid is returned to the mud storage tank for reuse. The drill cuttings separated from the wellbore fluid are collected and conveyed to storage tanks for treatment and disposal.
In most rotary drilling procedures, the wellbore fluid takes the form of a “mud,” i.e., a liquid having solids suspended therein. The solids function to impart desired rheological properties to the wellbore fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well. The drilling mud may be either a water-based or an oil-based mud. As such, the ability to suspend drilling cutting to reduce wear on the drill bit depends on the rheological properties of the drilling mud related to the viscosity of the wellbore fluid.
Wellbore fluids, including drilling muds, may consist of polymers, biopolymers, clays and organic colloids added to a water-based fluid to obtain the desired viscous and filtration properties. Heavy minerals, such as barite or calcium carbonate, may be added to increase density. Solids from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling. Further, wellbore fluids may contain one or more natural and/or synthetic polymeric additives, including polymeric additives that increase the rheological properties (e.g., plastic viscosity, yield point value, gel strength) of the drilling mud, and polymeric thinners and flocculents.
However, during the drilling process, the wellbore fluid may need to be monitored and/or altered frequently. For example, depending on the current drilling conditions, changes to the viscosity of the wellbore fluid may be critical, particularly when drilling deviated and/or horizontal wellbores. Previous techniques to determine the viscosity of wellbore fluids employ running the drilling mud through a calibrated funnel, such as a Marsh funnel, to record the time it takes to have the drilling mud pass through the funnel. Other techniques involve pumping samples of drilling mud from the mud pits at the surface of the well to measurement units, requiring additional plumping and maintenance for the measurement units.